Process for conditioning a high carbon dioxide content natural gas stream for gas sweetening

ABSTRACT

A process for pretreating a natural gas stream having greater than about 40 mole % CO 2  to reduce the amount of CO 2  in the gas stream prior to treatment in a conventional sweetening process comprising passing the gas stream through a separator zone which condenses the C 6  plus hydrocarbons and then passing the gas stream from the separator into a stripping zone which further reduces the temperature of the gas stream to remove a substantial quantity of CO 2  as a liquid condensate.

FIELD OF THE INVENTION

The present invention relates to a process for treating a high carbondioxide content gas stream, i.e., carbon dioxide content greater thanabout 40 mole percent. More particularly, the invention relates to amethod for treating such a high carbon dioxide content gas stream whichfirst removes therefrom the condensible C₆ plus hydrocarbon contentseparate from carbon dioxide, following which a bulk quantity of carbondioxide is separated from the gas stream as a high pressure, moderatelycold, liquid phase. The processed gas stream has its residual CO₂content reduced to a level which renders the gas stream amenable totreatment by conventional gas sweetening methods for recovery of the gasin marketable form.

BACKGROUND OF THE INVENTION

Natural gas, however produced, may contain acid gas impurities,particularly carbon dioxide and hydrogen sulfide. Such natural gas isreferred to as "sour gas," meaning that the "sweet" natural gas iscontaminated with an unacceptable quantity of "sour" acid gasimpurities. The presence in natural gas of such acid gas impurities isobjectionable, among other reasons, because of the corrosion problemsthey cause during pipeline transmission of the natural gas to market andbecause acid gas contaminants reduce the BTU content per standard cubicfoot of the natural gas product. Natural gas produced from a fieldhaving significant quantities of such acid gas components must betreated for removal of such impurities, or sweetened, before the naturalgas therefrom can be marketed. Of necessity, the treatment to sweeten anatural gas produced from such a field adds to its cost of production.The character and content of the acid gas components in the natural gasof the field can approach levels where the added cost of treating theproduced sour gas for removal of such impurities to produce a marketablesweet natural gas may make it uneconomical to exploit the gas field.

As noted, the processing of sour natural gas generally involves a gassweetening process that splits the sour natural gas into two processstreams: a sweet residue gas stream, and an acid gas stream. The sweetresidue gas stream, typically made up of methane and light hydrocarbonends, may go on to additional processing and hydrocarbon recovery ordirectly to gas sales. Impurities and sulphur compounds are removed fromthe acid gas stream leaving a carbon dioxide-rich acid gas stream. Oftenthe carbon dioxide-rich product is needed at high pressure for carbondioxide pipeline sales to enhanced oil recovery (EOR) projects or forreinjection into disposal wells. Alternatively, a high pressure carbondioxide gas stream may be flashed to a low pressure and coldtemperature, i.e., 90 psia, -60° F., and used to provide processrefrigeration.

In general, two basic approaches have been developed for use inprocessing natural gas containing significant quantities of carbondioxide for the removal of that acid gas impurity. One approach employsphysical solvents for the absorption and separation of the carbondioxide impurity from the natural gas. In the solvent approach, thecarbon dioxide containing natural gas is contacted countercurrently witha solvent in an absorption tower wherein the solvent physically absorbscarbon dioxide from the natural gas. Sweetened natural gas is recoveredas an overhead gas stream from the absorption tower. The carbondioxide-rich solvent is circulated to a regenerator vessel where thesolvent is usually regenerated by pressure reduction, that is, whenpressure on the carbon dioxide-rich solvent is reduced, carbon dioxideflashes out of the solvent as a gas. Hence, the solvent method producesa low pressure, vapor phase, carbon dioxide stream, and the regeneratedlean solvent is recirculated to the absorption tower. At typicalprocessing pressures, the required lean solvent circulation rateincreases with increasing carbon dioxide content of the natural gasstream under treatment. As a result, higher solvent circulation ratesare required to remove carbon dioxide from feed gases as the carbondioxide concentration of the feed gas increases.

A second basic approach for removing carbon dioxide from a natural gasstream is cryogenic fractionation. In such process, methane and lightercomponents are separated from carbon dioxide and heavier components in amulti-stage tower or fractionator. Typically, the fractionator has botha stripping section and a rectifying section. In the stripping section,heat is supplied to the bottom of the tower to vaporize lighthydrocarbon ends remaining in the liquified carbon dioxide bottoms,while in the rectifying section, condensed light hydrocarbons ends arerecirculated to the top of the tower as a reflux to cool and condensecarbon dioxide vapor remaining in the methane-rich vapor top ends. Forsuch separation to be achieved, the fractionator must operate atcryogenic temperature, i.e., temperatures in the range of -60° to -130°F. As a result, high compressor horsepower is required to provide theexternal process refrigeration or, if product stream carbon dioxide isexpanded for use as a refrigerant for operation of the cryogenicfractionator, to recompress the carbon dioxide.

Although both methodologies, physical solvents and cryogenicfractionation, can be applied to a high carbon dioxide content naturalgas stream, the cost of utilizing either type of process for thetreatment of a high carbon dioxide content natural gas stream, i.e.,carbon dioxide greater than 40 mole percent, can be prohibitivelyexpensive. In some special circumstances, cryogenic fractionation may beemployed for separation of the CO₂ content of a high carbon dioxidecontent methane gas stream to prepare a sales gas grade of methane. Onesuch special circumstance is with regard to landfill gas as discussed inU.S. Pat. No. 4,681,612. From the standpoint of odors and safety,landfill gas must be removed from the landfill site in any event. Sincethe cost of producing landfill gas and the quantities of such gas to beprocessed are minuscule in comparison to that of production of naturalgas from a natural gas field, employment of cryogenic fractionation toupgrade the methane content of such landfill gas to a marketablesales-gas quality may be justified on a cost basis.

However, the use of a physical solvent or a cryogenic fractionationprocess for the removal of carbon dioxide from a sour natural gasstream, by reason of the gas volumes involved, becomes exceedinglyexpensive when the carbon dioxide content is greater than about 40 mole%. The primary factors dictating the expense of treatment with regard toeither process is due to the large equipment requirements caused by thehigh gas volumes to be processed. Further adding to the expense whereincryogenic fractionation is utilized is the cost of special constructionmaterials. Whereas normal carbon steel can be used at temperature of-20° F. or greater, for operations at lower temperatures carbon steelmust be specially treated. For operation at cryogenic temperatures, -50°F. or less, special materials, such as nickel steels, are required. In acryogenic fractionation process, the cost of providing externalrefrigeration and/or recompression costs for carbon dioxide if it isused as a refrigerant by expansion, becomes prohibitive. The specialmaterials requirements taken together with the large equipment sizesrequired makes cryogenic fractionation economically unattractive.Likewise the physical solvent method is economically unattractive. Forinstance, in a physical solvent method that treats a natural gas streamcontaining 65 mole % carbon dioxide to produce 200 mscfd of market gradenatural gas requires about 400 kbpd of solvent circulation to theabsorber tower, and of course, the attendant cost of regeneration ofsuch solvent. Further, the solvent method produces the carbon dioxideproduct stream as a gas stream. For the CO₂ to be used for EORapplication or to be reinjected into disposal wells, it must berecompressed which adds extra cost.

As a consequence, the development of a method which significantlyreduces the cost of sweetening a high CO₂ content natural gas wouldgreatly add to the industry's motivation to develop and explore naturalgas fields wherein the natural gas contains more than about 40 mole %carbon dioxide. Several such fields are known to exist having produciblenatural gas containing carbon dioxide concentrations of 65-70 mole %with some fields being as high as 80-90 mole % carbon dioxide.

For such high carbon dioxide content natural gas fields to be viable forexploitation, it is necessary to develop a more cost effective processfor sweetening the natural gas from such fields to a marketable quality.It would be particularly desirable that such process be one whichremoves carbon dioxide as a high pressure moderately cold liquifiedproduct stream.

SUMMARY OF THE INVENTION

The new process provides for the bulk separation of carbon dioxide froma high carbon dioxide natural gas stream prior to final removal ofresidual carbon dioxide from such natural gas stream by a conventionalgas sweetening process. The new process readily reduces the carbondioxide content by a magnitude which conditions the natural gas streamfor economical treatment by physical solvent or cryogenic fractionationsweetening processes. Furthermore, the carbon dioxide removed from thenatural gas stream by the process of this invention is removed as aliquid carbon dioxide stream at relatively high pressure and moderatelycold temperature. The utilization of the process of this inventionupstream of a final carbon dioxide removal process significantly reducesdownstream processing costs and requirements for a final gas sweeteningprocess.

The pretreatment process of this invention comprises a two stage processthat removes a substantial quantity of the carbon dioxide content of thesour natural gas feed by liquifying and separating the carbon dioxide ata relatively high pressure and moderately cold temperature, i.e. attemperatures warmer than that required for CO₂ separation by cryogenicfractionation. The first step of the process is a separation stagewherein condensation of C₆ plus hydrocarbons and some carbon dioxide toliquids is accomplished. The second step of the process comprises astage of high pressure stripping of the overhead gas stream from theseparation stage which provides high liquid recovery of carbon dioxidewhile allowing methane condensed within the liquid CO₂ stream to berevaporized. The resultant gas stream after high pressure stripping hasa gas volume 20% to 60% less than that of the inlet sour natural gasstream feed to the separation stage.

The two stage pretreatment process of this invention is applicable tonatural gas stream containing CO₂ concentrations of about or greaterthan 40 mole %. Utilizing the two stage pretreatment process of thisinvention upstream of a final carbon dioxide removal process results inconsiderable cost savings due to reductions in both the total gas volumeand the amount of carbon dioxide to be treated for final gas sweeteningin a downstream gas sweetening process such as a physical solvent or acryogenic fractionation process. Cost savings are realized primarilythrough significant reductions in downstream equipment size,requirements for special construction materials and compressionhorsepower requirements in a final gas sweetening process.

DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic representation of a sour natural gas sweeteningprocess, wherein the process is of conventional prior art technique suchas cryogenic fractionation or physical solvent.

FIG. 2 is a schematic representation of the interface between theprocess of the invention, by which bulk CO₂ separation is performed onthe sour natural gas stream to precondition it for a final gassweetening treatment, and a conventional gas sweetening process.

FIGS. 3A and 3B are phase diagrams illustrating thetemperature-pressure, liquid-solid-vapor boundary conditions for severalhigh CO₂ content natural gas streams amenable to pretreatment by theprocess of the invention; the phase diagram of FIG. 3A, represented bysolid line, is for a gas stream of the composition 70 mole % CO₂, 27mole % CH₂, 2.5 mole % ethane and heavier hydrocarbon, and 0.5 mole % H₂S; the phase diagram of FIG. 3B, represented by a broken line, isillustrative of a natural gas stream containing 40 mole % CO₂, the phasediagram of FIG. 3B, represented by a dash-dot line, is illustrative of anatural gas stream containing 90 mole % CO₂.

FIG. 4 illustrates in flow schematic form one embodiment of apretreatment process in accordance with the invention.

FIG. 5 illustrates in schematic form the processing of the 70 mole % CO₂content natural gas stream of a composition as described in FIG. 3A bythe pretreatment process of the invention, followed by final sweeteningwith a conventional cryogenic fractionation process.

FIG. 6 illustrates in schematic form the processing of the 70 mole % CO₂content natural gas stream of a composition as described in FIG. 3A by aconventional cryogenic fractionator without pretreatment by a process ofthe invention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The process of the invention is intended to remove a sufficient quantityof the CO₂ content from a high CO₂ content natural gas stream as torender the pretreated gas stream amenable to gas sweetening byconventional gas sweetening processes at significantly reduced cost. Inthis regard, FIG. 1 schematically illustrates a conventional gassweetening process 10, which may be a physical solvent process asgenerally described in Fred C. Riesenfeld and Arthur L. Kohl, "GasPurification," Gulf Publishing Company, second edition, 1974, Chapter 2or a cryogenic fractionation process as described in "Two CombinedCryogenic Processes Cut Sour Natural-Gas Processing Cost," Robert D.Denton and David D. Rule, Oil and Gas Journal, Aug. 19, 1985.

For a natural gas to be amenable to treatment by such conventional gassweetening processes, it should contain no more than 40 mole % CO₂. Suchnatural gas stream may be one which contains more than 40 mole % CO₂ byreason of the conditions of the gas field itself or by reason that CO₂has been injected into the field as a drive fluid and is recovered withnatural gas produced during an enhanced oil recovery (EOR) operation.Hence, conventional sweetening processes, as illustrated in FIG. 1,become exceedingly expensive or cost prohibitive for application tonatural gas streams having greater than 40 mole % CO₂. The conditions oftemperature and pressure of the process of this invention enable the useof standard construction materials, i.e. normal carbon steel, forpractice of the process. Consequently at the temperature ranges withinwhich the process operates a natural gas stream having a CO₂ contentless than 40 mole % is not suited to treatment by the process of theinvention since its gas volume will not be significantly reduced by suchtreatment. Further, a gas stream having less than 10 mole % hydrocarboncontent would have so little marketable quantity of hydrocarbon productthat its treatment by a process of the invention would not be warrantedfrom the standpoint of improving the economy of treating such gas by afinal sweetening process for recovery of the natural gas component inmarketable form. Consequently, natural gas streams which are the mostsuitable candidates for treatment by the process of the invention arethose containing from about 40 to about 90 mole % carbon dioxide.Pretreatment of such high CO₂ content natural gas streams by the processof the invention significantly reduces the cost at which the resultinggas stream may be treated by a final sweetening process of conventionaldesign.

The process of the invention may be employed to precondition a high CO₂content natural gas stream for economical final gas sweetening by aconventional gas sweetening process. FIG. 2 illustrates the interface ofthe process of the invention 12 with a conventional gas sweeteningprocess final stage 10.

FIG. 4 illustrates an embodiment of the pretreatment process of theinvention. The process consists of two basic stages: namely, aseparation stage 14 and a high pressure stripping stage 28. Typicaloperating points for the two stages of the process are illustrated onthe phase diagrams of FIG. 3A for an actual 70 mole % CO₂ contentnatural gas stream as point "a" for the high pressure stripping stageand point "b" for the separation stage.

For convenience the first stage 14 of the pretreatment process isreferred to as "separation." In the first or separation stage of theprocess, dehydrated sour natural gas 16 is first cooled by heat exchangein heat exchanger 18 and passed by inlet line 19 to a separator vessel20 designed for vapor-liquid separation. Condensed liquids, primarilycondensate (C₆ plus hydrocarbons) and some CO₂, are separated andremoved in separator 20. The condensate liquid is removed from separator20 by outlet line 22. The overhead vapor or remaining gas stream ispassed by overhead line 24 to further processing, as in high pressurestripping stage 28, or to yet another separator vessel 20' if desired.

One or two cooling/separation vessels 20 and 20' may be used dependingon the exact nature of the produced fluid. Wherein, by reason of theinlet gas stream composition, it is preferred to employ a second stageof separation as per a second separator 20' as illustrated, the overheadgas passing by overhead line 24 from the first separator 20 ispreferably passed through a heat exchanger 26 for additional cooling.Generally, cooling in the heat exchangers 18 and 26 may be provided bycooling water or process heat exchange. External refrigeration is notrequired. The separators 20 and 20' are two phase pressure vessels andshould have adequate area to separate the gas and liquid phases.

The operating conditions must be such that the separators 20 and 20'operate in the two phase region shown in FIG. 3A or 3B where themajority of the heavy hydrocarbons condense without the lighthydrocarbon ends. Hence, the appropriate pressure and temperature shouldbe selected to maximize recovery of liquid hydrocarbons. (See operatingpoint "b" in FIG. 3A for a 70 mole % CO₂ natural gas stream.) Typicaloperating conditions range from 600 to 1200 psia and 30° to 80° F.

As illustrated in FIG. 4, more than one separation stage may beprovided, if desired. If more than one separation stage is provided, theseparator vessels should operate at successively lower pressures andtemperatures to improve separation efficiency and enhance the overallrecovery of the hydrocarbon liquids. Additional separation stages willminimize downstream processing requirements for hydrocarbon recovery.

The liquids passed by line 23 from the separation stage may be fed to astabilizer for hydrocarbon recovery, used as fuel for gas-firedequipment, used for process cooling, fed to the high pressure stripperfor methane recovery, or pumped for reinjection.

For convenience, the second stage 28 of the pretreatment process isreferred to as "high pressure stripping." Here, a bulk quantity of theCO₂ content of the sour natural gas stream issuing from the separationstage is condensed and separated from the natural gas stream with only asmall amount of methane and other light hydrocarbon ends. Vapor leavingthe separator stage by line 24, or alternatively 24', is the feed gasstream to the high pressure stripping stage 28. The feed gas stream isfirst chilled by either refrigeration in a heat exchanger 30 orexpansion through a power recovery turbine 32 and then fed by line 34 tothe high pressure stripper 36. Refrigeration may be provided by processheat exchange or an external refrigeration system.

The high pressure stripper 36 may be either a packed or trayed strippingcolumn. The chilled gas stream from line 34 enters the top 38 of thestripping column 36. Operation at the top of the stripping column isreflected by point "a" of FIG. 3A for a 70 mole % CO₂ natural gasstream. Heat is supplied to the bottom 40 of the column by circulationof a portion of the CO₂ -rich liquid stream from outlet line 48 throughline 44 to a reboiler 42 by an external source such as hot oil orprocess heat exchange. The heated CO₂ -rich stream is returned fromreboiler 42 by line 46 to the bottom 40 of column 36 to revaporize lighthydrocarbon ends remaining in the CO₂ -rich liquid accumulated in thebottom of the column. The reboiler temperature is set so that only asmall amount of the methane is left in the CO₂ -rich liquid. Thereboiler temperature should be set to maintain a temperature in theliquid phase accumulated in the bottom of the column near the bubblepoint of pure CO₂. The reboiler on the high pressure stripper 36 therebyallows the condensed methane to be revaporized while maintaining highliquid recovery of the CO₂.

The CO₂ -rich, stripper bottoms are removed by outlet line 48 and may bepumped for reinjection or CO₂ sales, or used for process cooling duringrevaporization. The methane-rich vapors exiting the top of the columnthrough line 50 are sent to a final CO₂ removal process, such as solventtreating, cryogenic fractionation, or other cryogenic processes, such asthose disclosed in U.S. Pat. No. 4,533,372. The CO₂ content of themethane-rich gas leaving the stripper through line 50 ranges from about30 to 50 mole percent, depending on the process operating conditions.Because the vapor exiting the top of the column is processed further, arectifying section is not needed in the stripper column itself.

The operating conditions of the high pressure stripper are set toprovide bulk removal of the CO₂ while minimizing methane losses. Theoperating pressure must be below the critical pressure of the mixtureand should be optimized based on both the upstream and downstreamprocess conditions. Generally, the pressure is maintained at as high alevel as possible in order to minimize the cost of further handling ofthe CO₂ -rich liquid and the methane-rich vapor.

The operating temperatures of the stripper 36 have the greatest impacton the process. The gas stream feed in line 34 to the stripper should bechilled to temperatures in the range of about 0° to -20° F. Temperaturesin this range maximize the amount of CO₂ condensed, minimizerefrigeration requirements and allow normal carbon steel materials to beused in the equipment design. The reboiler temperature and the number ofseparation stages of column 36 determine the amount of methane that islost to the CO₂ -rich liquid. Typically, reboiler temperatures are onthe order of 30° to 80° F. with about 6 to 15 theoretical separationstages.

The operating ranges discussed above are with reference to a 70 mole %CO₂ gas stream as illustrated by FIG. 3A and are for illustration;actual process operating conditions should be selected and optimized foreach specific application, which may be readily determined based uponthe precise composition of the gas stream to be treated.

As may be seen from FIGS. 3A and 3B and the phase envelope lines thereonfor a 40, 70 and 90 mole % CO₂ content natural gas stream, the selectionof the precise operating conditions for the separation and stripperstages depends upon the composition of the gas stream to be treated. Theoperating window for temperatures and pressures is narrow when treatinga 40 mole % CO₂ content gas stream, but progressively broadens as CO₂content increases up to the 90 mole % level (FIG. 3B). Generally, for a40 mole % CO₂ content gas stream the separator stage must be set foroperation at about 0° F. and a pressure of from about 1100 to about 1200psia while the stripper stage is operated with a gas inlet temperatureof about -20° F. and a pressure of about 1100 to 1200 psia. For a 90mole % CO₂ content gas stream the separator stage may be set foroperation at an inlet gas temperature of up to about 60° F. at apressure of about 950 psia and the stripper operated at an inlet gastemperature from about 0° F. to about -20° F. at gas pressuresrespectively from about 800 psia to about 675 psia.

FIG. 5 illustrates the process of the invention 12 as integrated with acryogenic fractionation process 60 of conventional design as a final gassweetening stage, as applied to a sour natural gas stream 16 of the 70mole % CO₂ content composition as illustrated by the phase diagram ofFIG. 3A. For such a sour natural gas stream, for the gas volumes andconditions of temperature and pressure illustrated in FIG. 5, thecompositions, gas volumes, process horsepower and equipment sizerequirements are described. The dehydrated feed gas is cooled to 40° F.and condensed hydrocarbon liquids and a small amount of CO₂ areseparated. The gas is then chilled to -3° F. and enters the highpressure stripper operating at 900 psia. The CO₂ content of the vaporsleaving the stripper is reduced from 70 mole % to 50 mole %, resultingin a 50% reduction in total gas volume to be finally treated in aconventional cryogenic gas sweetening process 60. In the cryogenicfractionation stage 62, the CO₂ content is reduced to 17 mole % and themethane-rich gas is sent by line 64 to final treating 66 to produce thefinal sales gas 68. The CO₂ -rich liquid streams 25 from the stripper 28and the cryogenic fractionation stage 62 are pumped by pumps 72 to highpressure for reinjection. Low temperature process refrigeration issupplied by an external refrigerant. The total horsepower requirement isestimated to be about 275 kBHP. The high pressure strippers (18 ft.ID×65 ft. H) are required to process the full raw gas rate. The gasvolume leaving the stripper, about 1.5 Bscfd, may be treated by threecryogenic fractionators (10 ft. ID×73 ft. H).

FIG. 6 illustrates the use of cryogenic fractionation process 60 fortreatment of a 70 mole % CO₂ content gas stream of the composition asillustrated by the phase diagram of FIG. 3A without pretreatment by theprocess of the invention. For the gas volumes and conditions oftemperature and pressure required for cryogenic separation of CO₂ asillustrated in FIG. 6, the compositions, gas volumes, process horsepowerand equipment size requirements are described. The dehydrated feed gasis chilled by external refrigeration 76 and CO₂ refrigeration 78° to-62° F. and fed to a fractionation stage 62 operating at 600 psia. Theoverhead methane-rich vapors 64 contain about 20 mole % CO₂ and are sentto final processing 66 and from there by line 68 to gas sales. The bulkof the CO₂ -rich liquid passed by line 70 from the fractionation stage62 is pumped by pump 72 to high pressure for reinjection into thereservoir. Approximately twenty-six percent of the CO₂ -rich liquid ispassed by line 74 to refrigeration unit 78 to provide low-temperatureprocess refrigeration prior to compression 80 to reinjection pressure.The total process horsepower requirement is estimated to be 455 kBHP.Three cryogenic fractionators (not shown in the drawings) offractionation stage 62 (19 ft. ID×105 ft. H) process the full raw gasrate of about 3 Bscfd.

By pretreating the dehydrated raw gas with the pretreatment process ofthe invention, as illustrated in FIG. 5, before subjecting the gasstream to cryogenic fractionation, the total process horsepower requiredfor final cryogenic fractionation is reduced by 40% for a total of about275 kBHP. Without pretreatment by the process of the invention threecryogenic fractionators (19 ft. ID×105 ft. H) are required to handle thefull raw gas rate of 3 Bscfd in a cryogenic fractionation process;however, by pretreating the gas with the process of the invention asillustrated in FIG. 5, after treatment in three high pressure strippers(18 ft. ID×65 ft. H), the three cryogenic fractionators (10 ft. ID×73ft. H) are required to handle only 50% of the raw gas rate, or about 1.5Bscfd.

The impact of the bulk CO₂ separation by pretreatment of the gas streamby the process of this invention to precondition a 70 mole % CO₂ contentnatural gas stream of the composition as illustrated by FIG. 3A forfinal gas sweetening with a physical solvent instead of the cryogenicfractionator has been reviewed. Preliminary calculations indicate apotential reduction in the solvent circulation rate by a factor of fourwhen the pretreatment process of this invention is installed upstream ofthe solvent process.

Pretreatment of a high CO₂ content natural gas stream by the process ofthis invention accomplishes a reduction of both the total gas volume andthe amount of CO₂ to be handled by the final CO₂ removal process. Theprocess of this invention removes carbon dioxide in the liquid phase ata relatively high pressure and moderately cold (non-cryogenic)temperature.

Utilization of the process of this invention to pretreat a high CO₂content natural gas prior to its final treatment in a gas sweeteningprocess of conventional design permits significant cost saving to berealized in operation of the final gas sweetening process as follows:significant downsizing of equipment regardless of the final removalprocess selected can be accomplished since the total feed gas volumescan easily be reduced by 20 to 60 percent by the pretreatment process;substantial reduction in refrigeration and associated horsepowerrequirements for cryogenic fractionation processes; reduction ofcirculation rates for solvent processes; substantial reduction indownstream compression or pumping horsepower requirements when the CO₂is to be sold or reinjected; separation of CO₂ as a liquid stream in thepretreatment process permits its use to provide low temperature, processrefrigeration by revaporizing the liquid CO₂ thereby reducing processutility requirement; reduction in dehydration requirements for cryogenicprocesses by using the solvent ability of carbon dioxide for final waterremoval prior to processing at cryogenic temperatures; and flexibilityto allow the bulk separation/final removal process to be optimized.

The invention has been described with reference to its preferredembodiments. Those of ordinary skill in the art, upon review of thisdisclosure, may appreciate variations which may be made which do notdepart from the scope and spirit of the invention as described above orclaimed hereafter.

I claim:
 1. A process for pretreating a natural gas stream havinggreater than about 40 mole % carbon dioxide to remove therefrom asubstantial quantity of the carbon dioxide as a high pressure liquefiedproduct stream, comprising the steps of:passing said gas stream througha separator zone at a temperature of from about 30° to about 80° F.while said gas stream is maintained at a pressure of from about 600 psiato about 1200 psia to remove from said gas stream as a liquid condensatethose gas components which are condensible at said temperature andpressure; removing the liquid condensate from the separator zone;feeding the gas stream from the separator zone through a stripping zoneat a temperature of from about -20° to about 0° F. while maintainingsaid gas stream at a pressure of from about 600 psia to about 1200 psiato remove from said gas stream a substantial quantity of the carbondioxide content as liquefied carbon dioxide.
 2. The process of claim 1,wherein the liquefied carbon dioxide removed has a temperature fromabout 30° to about 80° F. and a pressure of from about 600 psia to about1200 psia.
 3. The process of claim 1, wherein the volume of the gasstream exiting the stripping zone is 20 to 60% less than the volume ofthe natural gas stream passing into the separator zone.
 4. The processof claim 1, wherein the carbon dioxide content of the gas stream exitingthe stripping zone ranges from about 30 to about 50 mole percent.
 5. Theprocess of claim 1, wherein the natural gas stream has less than about90 mole % carbon dioxide.
 6. The process of claim 1, wherein theseparator zone comprises more than one separation vessel.
 7. The processof claim 1, wherein the stripping zone comprises a packed or trayedstripper column.
 8. The process of claim 1, further comprisingprocessing said gas stream from said stripping zone in a cryogenicsweetening process wherein the carbon dioxide content of said gas streamis further reduced.
 9. The process of claim 1, further comprisingprocessing said gas stream from said stripping zone wherein additionalcarbon dioxide in said gas stream is absorbed by a solvent.
 10. Aprocess for pretreating a natural gas stream having from about 40 toabout 90 mole % carbon dioxide to remove therefrom a substantialquantity of the carbon dioxide as a high pressure liquefied productstream, comprising the steps of:passing said gas stream through aseparator zone at a temperature of from about 30° to about 80° F. whilesaid gas stream is maintained at a pressure of from about 600 psia toabout 1200 psia to remove from said gas stream as a liquid condensatethose gas components which are condensible at said temperature andpressure; removing the liquid condensate from the separator zone;feeding the gas stream from the separator zone through a stripping zoneat a temperature of from about -20° to about 0° F. while maintainingsaid gas stream at a pressure of from about 600 psia to about 1200 psiato remove from said gas stream a substantial quantity of the carbondioxide content as liquefied carbon dioxide, thereby reducing the carbondioxide content of the gas stream exiting the stripping zone to a rangefrom about 30 to about 50 mole percent.
 11. The process of claim 10,wherein the liquefied carbon dioxide removed has a temperature fromabout 30° to about 80° F. and a pressure of from about 600 psia to about1200 psia.
 12. The process of claim 10, wherein the volume of the gasstream exiting the stripping zone is 20 to 60% less than the volume ofthe natural gas stream passing into the separator zone.
 13. The processof claim 10, wherein the separator zone comprises more than oneseparation vessel.
 14. The process of claim 10, wherein the strippingzone comprises a packed or trayed stripper column.
 15. The process ofclaim 10, further comprising processing said gas stream from saidstripping zone in a cryogenic sweetening process wherein the carbondioxide content of said gas stream is further reduced.
 16. The processof claim 10, further comprising processing said gas stream from saidstripping zone wherein additional carbon dioxide in said gas stream isabsorbed by a solvent.